Core analysts concerned with determining the nature of rock and fluid contained underneath the ground will often extract a core from, for example, an oil well and create core samples. The analysts will then conduct tests on the core samples to determine the core's characteristics.
One important characteristic of a core sample is relative permeability. Relative permeability relates to the flow characteristics of one fluid relative to a second fluid contained in the core sample. An important parameter in determining relative permeability is the saturation state of the sample—that is, the percentage of space (pore volume) in the sample that contains a first fluid, such as brine, and the percentage of that volume that contains a second fluid, such as oil. The measurement of relative permeability is often plotted as a function of sample saturation state.
Determining relative permeability is often done by the steady state method. This method involves choosing various fluid percentages to flow through the core sample until the fluid flow reaches steady state. For example, the core sample can be 100% brine saturated and a user can flow 100% oil into the core sample. Since the core sample is initially 100% brine saturated, initially the effluent from the core sample will also be 100% brine. However, the effluent will eventually include oil as the oil flows through the core sample, resulting in an effluent that is part oil and part brine. Once the oil flowing into the sample pushes all the brine that is able to be pushed out of the sample, the effluent will be 100% oil, resulting in a steady state or equilibrium, condition. In other words, steady state is achieved when flow of fluid into the core sample (100% oil) is the same as flow of fluid out of the core sample (also 100% oil).
The sample is now partially saturated with oil and partially saturated with brine (e.g., all the brine that is able to be flushed from the core sample has already been pushed out). The user determines the amount of brine remaining in the sample by measuring the volumes of oil and brine that have been flowed into the sample and the volumes that have gone out, and thereby determines the relative percentages of oil and brine remaining in the sample (i.e., the sample's saturation state).
In this sample case, the user then flows a different percentage of oil and brine into the core sample—say, 70% oil and 30% brine—until the system reaches a steady state or equilibrium, i.e., effluent that is also 70% oil and 30% brine. By determining the fluid volumes in and fluid volumes out, the user can then determine the core sample saturation state under those conditions, which will likely be different than when flowing 100% oil. The user then flows another percentage of oil and brine—say, 30% oil and 70% brine—until equilibrium is reached, similarly determining the sample saturation state under those conditions. The final percentage of fluid flow in may be 100% brine, with the sample saturation state determined using the same method.
In each of these cases, a large volume of fluid may need to be flowed through the core sample before equilibrium or steady state is achieved. If this large volume exceeds the finite volume of the traditional two-phase separator or similar system, the relative volumes of the two fluids can no longer be measured and the calculation will fail. Traditional two-phase separators also have the limitation of only being able to measure the change in volume of one of the two effluent fluids. This limitation makes it difficult to track the effluent flow rate of the second phase and accurately determine when steady state has been reached and the saturation state of the core sample. Therefore, there exists a need for an apparatus, method, and/or system that can accommodate and measure large volumes of fluid in order to determine sample saturation state.